The U.S. Department of Energy’s National Energy Technology Laboratory says technically recoverable gas hydrate resources on Alaska’s North Slope are some 85 trillion cubic feet of undiscovered gas resources within hydrates that can be recovered using existing technologies.
Existing technologies include producing gas from gas hydrate by “depressurization using standard drilling and completion methods,” NETL said earlier this year.
But ConocoPhillips is preparing to field test a process for producing gas from gas hydrates by exchanging carbon dioxide for the methane without dissociating the methane from the water in the hydrate structure, i.e. substituting CO2 for methane held in the lattice structure of gas hydrate, leaving the hydrate structure intact — and providing a storage option for CO2.
The process, patented by ConocoPhillips, was developed in the laboratory, David Schoderbek told the Alaska Support Industry Alliance Sept. 24.
While the process is years from being commercial, a field test is planned for 2011 to scale the process up from desk-top scale in the laboratory to reservoir scale, said Schoderbek, the gas hydrates team leader for ConocoPhillips Alaska.
Alaska’s gas hydrate endowment is “extraordinary,” he said, and the laboratory technology “of exchanging methane and CO2 in the hydrate formation without dissociating it is a game-changing technology.”
The field test will be co-funded by ConocoPhillips and the U.S. Department of Energy, with planning for the trial under way by a team of engineers, geoscientists and permitters at ConocoPhillips.
The hydrate cageIn methane hydrates a “cage or lattice of water surrounds a captive molecule of methane,” Schoderbek said. Hydrates form in nature in situations with high pressure and low temperature — at the bottom of the ocean and in permafrost.
In deep marine settings the temperature at the seafloor is near zero; in the Arctic hydrates form in and below the permafrost.
There may be as much gas trapped as hydrate as is present in all fossil fuel resources, he said, but the majority of hydrates exist in deep marine settings where the reservoir quality is low and the concentration of hydrates is low.
But, he said, referring to a U.S. Geological Survey pyramid of the methane hydrate resource, “the upper two tiers of that pyramid are Arctic hydrates trapped subpermafrost.” And Alaska has hydrates “adjacent to or near infrastructure,” he said.
Technologies used to produce gas from hydrates include depressurization, thermal stimulation and inhibitor injection and were developed when gas hydrates were first found in pipes “when pressure-temperature conditions were such that gas and water would form a plug in pipes.” Depressurization, thermal stimulation and inhibitor injection were used on the surface in piping and also applied in the subsurface to produce methane hydrates.
“All three of those techniques, however, dissociate or melt the hydrate so you’re left with water and gas,” Schoderbek said.
The North Slope hydrate reservoirs are poorly consolidated, which “can result in sand production as well as water production,” which could lead to subsidence.
Exchange technologyConocoPhillips has been working on an exchange technology — CO2 for methane — in the laboratory for about six years, in conjunction with the University of Bergen in Norway, Schoderbek said.
The original hydrate work took place at the phase boundaries of carbon dioxide and methane, an extension of hydrate plugs that form in pipes. But that process is slow and is associated with the release of water and re-formation of hydrates, he said.
“We predicted — and have proven in the laboratory — that at slightly higher pressures and slightly lower temperatures this exchange can be much more efficient and faster as well,” Schoderbek said.
Most of the laboratory work has been done closer to 40 degrees Fahrenheit and 1,000 pounds per square inch, the conditions present in North Slope hydrate reservoirs.
Under laboratory conditions carbon dioxide displaces methane in the hydrate structure.
“And what excites us the most about this is we don’t see any evidence of dissociation or melting of the hydrate; no water is produced with this methane,” he said.
All of the methane in the large cage structure, 70 percent of the methane in the hydrate, is displaced by CO2. The 30 percent of methane not displaced is in an area of the cage structure that is too small for CO2 to enter, Schoderbek said.
Because the exchange takes place without dissociation there’s no melting and refreezing and, he said, the mechanical strength of the hydrate is not expected to be affected.
Goal of field trialThe goal of the field trial is to “take this laboratory experiment — that has been a desktop scale — and expand it to reservoir scale.”
“The main goals are to confirm that we can inject CO2 into these naturally occurring hydrates and confirm that exchange takes place without dissociation and production of water and sand,” Schoderbek said.
He emphasized that this test will not demonstrate whether the process is commercial.
ConocoPhillips will use an ice pad or existing gravel pad so there will be no new disturbance on the North Slope. Chilled drilling mud will be used to protect the permafrost and low-pressure cement will be used.
A coiled tubing drilling rig will be used to minimize the impact on North Slope development drilling.
Once drilling is complete CO2 will be injected and the well will be shut-in and then the volumes will be tested.
The well will then be plugged and abandoned.
The project is expected to take about two months.
To select a well for testing they began with some 5,700 wells drilled in areas identified by USGS as being in hydrate-prone areas. From that group some 1,000 wells with the right logs to identify methane hydrates were selected.
Those candidates were then ranked by thickness, number of sands saturated with hydrates, percentage of pores estimated to be filled with hydrates, strength of shows encountered when the wells were drilled and expected pressure and temperature.
Steps to commercialityA number of steps will be required to demonstrate commerciality.
The first is drilling the field trial.
“Providing that is successful, we’ll move to a longer-term injectivity study,” and will also need a longer-term supply of CO2.
If that test is successful, a two-well displacement study will follow, then a multiwell displacement test with a CO2 flood.
It is expected to take more than 10 years to move through these steps, Schoderbek said.
The initial test will be small volume, he said.
“How fast that comes out is going to be a function of the pressure and permeability,” but the rate for the test will probably be 100,000 cubic feet a day, with the initial test affecting perhaps only 20 feet into the reservoir.
DOE wants synergy between the ConocoPhillips project and the ongoing BP pressurization project, “so we’re right now in the process of bringing those two projects into alignment.”
“Our current estimate is that this test will take place winter 2011,” he said.
BP and DOE ran a successful gas hydrate stratigraphic test well, Mount Elbert, in 2007, and are working on plans for a first-of-its-kind long-term gas hydrate production test. ASRC Energy Services, Ryder Scott Co., USGS, DOE, the University of Alaska Fairbanks and the University of Arizona have all been collaborating on the project.
DOE and the North Slope Borough are investigating the possibility that gas hydrates are contributing to production from gas fields near Barrow on the west side of the North Slope, as production from a couple of wells near Barrow has remained near constant for decades, leading to a theory that gas hydrate dissociation is maintaining gas pressure in at least one of the Barrow gas fields.